Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a significant amount of added emphasis has been placed on overall well architecture, monitoring and follow-on interventional maintenance. Careful attention to the cost effective and reliable execution of completing such wells and carrying out such applications may help maximize production and extend well life. Thus, a substantial return on the investment in the completed well may be better ensured.
In line with the objectives of maximizing cost effectiveness and overall production, the well may be fairly sophisticated in terms of architecture. For example, the well may be tens of thousands of feet deep, traversing various formation layers, and zonally isolated throughout. That is to say, packers may be intermittently disposed about tubing such as production tubing which runs through the well so as to isolate various well regions or zones from one another. Thus, production may be extracted from certain zones through the production tubing, but not others. Indeed, the particular zones from which production is sought may change over the life of the well as the production profile changes. Additionally, production tubing may ultimately terminate adjacent a production region where it is generally anchored or immobilized in place thereat by a mechanical packer, irrespective of any other zonal isolation thereabove.
In the majority of circumstances, the packers utilized to achieve the zonal or terminal isolations noted are mechanical packers that may be “set” in a variety of different manners. That is, as opposed to swell packers that are made up of a swellable elastomer which achieves an isolating seal over a period of time, mechanical packers are deployed to a target location and then driven to expand and seal at the location. The triggering of this setting is generally achieved with a setting tool which includes a hydraulic piston in communication with compressible features of the packer. Specifically, a stroking of the piston may be used to forcibly actuate the packer into setting engagement with a casing defining the well wall. This may include teeth or slips of the packer as well as seal members engaging the wall for sake of anchoring and sealing at the location.
Different techniques may be utilized which allow an operator at the surface of the oilfield to trigger the setting tool for sake of stroking the piston and setting the packer as noted above. For example, a hydraulic or electric line may run from power equipment at the oilfield surface adjacent the well to allow the operator to trigger the setting action. Unfortunately, this requires the addition of the line running potentially several thousand feet through the well in order to reach the setting tool. Setting aside the added cost of the line, this also means that packer setting is dependent upon potentially several thousands of feet of line remaining reliably unharmed during deployment and exposure to the downhole environment.
In order to avoid the added expense and potential failure of a line running to a setting tool, the setting tool may be triggered without use of a line. Instead, the operator may make use of fluid pressure in the well to direct the setting tool to initiate setting of the packer at the appropriate time. For example, once the tubing which accommodates the packer is fully installed, a plug may be run through the interior of the tubing and to a location below the packer and setting tool. From the oilfield surface, the operator may then drive up pressure within the tubing to create a predetermined pressure differential between the tubing interior and the annular pressure between the tubing and the well wall. The piston of the setting tool may ultimately be in fluid communication with both the annular space and the interior of the tubing such that once a predetermined differential is reached, the piston may stroke for setting of the packer.
Unfortunately, triggering the setting tool to set the packer by way of pressurizing the interior of the tubing presents another set of potential issues. For example, a plug must be deployed through the interior of the tubing before pressurizing may begin. Indeed, following packer setting, the plug will also be removed so that access to tubing locations further below the packer may be available. This means that a substantial amount of time may be required in added interventional trips for sake of plug installation and retrieval. Once more, the plug, tubing, valves within the tubing and a host of other devices therein may all be of limited pressure tolerances, perhaps under about 5,000 PSI. Thus, in circumstances where the annular pressure outside of the tubing is over 5,000 PSI, the operator would be forced to exceed these tolerances in order to create a sufficient differential for actuating the setting mechanism. In other words, the act of triggering the setting mechanism would be likely to damage the plug, tubing or other internal devices. Indeed, this is increasingly common as wells become deeper and deeper, often displaying annular pressures in excess of 5,000-10,000 PSI or more.
As an alternative to using a differential setting technique as described above, setting tools are available that do not rely on differential pressure for triggering. For example, a hydrostatic set module may rely on pressure supplied solely by the annular space. However, such tools are generally reliable where the annular pressure is below about 10,000 PSI. Thus, as a practical matter, as wells are increasingly of greater depths and pressures, the setting tool often remains tethered to surface equipment for sake of actuation, unable to take advantage of less cumbersome pressure actuating techniques.